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WO2019060844A2 - Procédé de poly-génération de dioxyde de carbone (co2) pour une récupération tertiaire d'huile améliorée, et génération d'énergie sans carbone pour l'exploitation de champs pétrolifères à l'aide d'un combustible résiduaire émulsifié à faible coût - Google Patents

Procédé de poly-génération de dioxyde de carbone (co2) pour une récupération tertiaire d'huile améliorée, et génération d'énergie sans carbone pour l'exploitation de champs pétrolifères à l'aide d'un combustible résiduaire émulsifié à faible coût Download PDF

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Publication number
WO2019060844A2
WO2019060844A2 PCT/US2018/052473 US2018052473W WO2019060844A2 WO 2019060844 A2 WO2019060844 A2 WO 2019060844A2 US 2018052473 W US2018052473 W US 2018052473W WO 2019060844 A2 WO2019060844 A2 WO 2019060844A2
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WO
WIPO (PCT)
Prior art keywords
carbon dioxide
carbonaceous particles
internal combustion
sulfur
liquid
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2018/052473
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English (en)
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WO2019060844A3 (fr
Inventor
Michael Williams
Mark DE JAGER
Henry Gil
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Accel Energy Canada Ltd (alphahawk Carbon Capture Eco-System For Liquids)
Original Assignee
Accel Energy Canada Ltd (alphahawk Carbon Capture Eco-System For Liquids)
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Filing date
Publication date
Application filed by Accel Energy Canada Ltd (alphahawk Carbon Capture Eco-System For Liquids) filed Critical Accel Energy Canada Ltd (alphahawk Carbon Capture Eco-System For Liquids)
Publication of WO2019060844A2 publication Critical patent/WO2019060844A2/fr
Anticipated expiration legal-status Critical
Publication of WO2019060844A3 publication Critical patent/WO2019060844A3/fr
Ceased legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K23/00—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids
    • F01K23/02—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled
    • F01K23/06—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle
    • F01K23/064—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle in combination with an industrial process, e.g. chemical, metallurgical
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Definitions

  • the disclosure relates generally to methods and systems to generate high quality carbon dioxide for enhanced oil recovery from miscible and/or immiscible oil reservoirs and particularly to a method and system that utilizes emulsified low-cost fuel sources for internal combustion engines to generate carbon, with oxygen-fired combustion or air, to poly-generate electrical power for oilfield consumption or sale.
  • Oil is a non-renewable natural resource having great importance to the
  • Some embodiments of the present disclosure include a process having the steps of forming an aqueous slurry of carbonaceous particles, combusting the aqueous slurry carbonaceous particles in an engine to form a carbon dioxide-containing product and generate electrical energy, and injecting at least a portion of the carbon dioxide-containing product into a well to assist in recovering a hydrocarbon from a subterranean deposit.
  • the carbonaceous particles can have a mean and median size of at least about 1 microns but no more than about 90 microns.
  • the aqueous slurry of carbonaceous particles can have one or more of an emulsifier and surfactant.
  • the carbonaceous particles be one or more of petroleum coke, coal, and biomass.
  • the carbonaceous particles can be one of more of liquid petroleum residues, lube oil, and fuel oil.
  • the carbon dioxide-containing product can also contain a sulfur oxide.
  • the carbonaceous particles can be a liquid petroleum residue.
  • the carbonaceous particles can be a lube oil.
  • the carbonaceous particles can be a fuel oil.
  • the carbonaceous particles can be a petroleum coke.
  • the carbonaceous particles can be coal.
  • the carbonaceous particles can be a biomass.
  • the median, mean, and P90 sizes of the emulsification fuel particles can be of no more than about 90 microns, more typically of no more than about 75 microns, more typically of no more than about 65 microns, more typically of no more than about 60 microns, more typically of no more than about 55 microns, and more typically of no more than about 45 microns.
  • the median, mean, and P90 sizes of the emulsification fuel particles can commonly range from about 1 to about 55 microns, more commonly from about 2.5 to about 25 microns, and more commonly from about 5 to about 10 microns.
  • emulsification fuel can range from about 1 to about 70 vol.% solids and more typically from about 1 to about 60 vol.% solids.
  • the process can include a step of recovering the sulfur oxide from the carbon dioxide-containing product.
  • the process can include a step of converting the sulfur oxide into one or more of elemental sulfur, sulfuric acid, and ammonium sulfate through the use of one or more of an air independent cycle and an air dependent integrated combustion process cycle.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by one or more of ammonia-water refrigeration and a heat recovery power cycle, organic and inorganic heat Rankine refrigeration and power cycles, propane and carbon dioxide compression refrigeration and power cycles, and cryogenic air processes to refrigerate and capture.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by ammonia-water refrigeration and heat recovery power cycle.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by organic heat Rankine refrigeration and power cycles.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by inorganic heat Rankine refrigeration and power cycles.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by a one or more of ammonia-water refrigeration and propane and carbon dioxide compression refrigeration.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by air processes refrigeration and capture.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by inorganic heat Rankine refrigeration and power cycles.
  • the process can include a step of recovering carbon dioxide from the carbon dioxide-containing product by organic heat Rankine refrigeration and power cycles.
  • the engine is an internal combustion engine.
  • the internal combustion engine can be a reciprocating internal combustion engine.
  • the internal combustion engine can an internal combustion turbomachine.
  • the internal combustion engine can be a combination of a reciprocating internal combustion engine and an internal combustion turbomachine
  • the carbon dioxide-containing product can contain a sulfur oxide.
  • the process can include the step of recovering the sulfur oxide from the carbon dioxide-containing product.
  • the process can include the step of and converting the sulfur oxide into hydrogen sulfide as feed to a Claus process to manufacture elemental sulfur.
  • Some embodiments include a cryogenic product from an air separation unit.
  • the air separation unit can cryogenically capture carbon dioxide from the carbon dioxide-containing product.
  • the air separation unit can cryogenically capture sulfur oxides from the carbon dioxide-containing product.
  • the air separation unit can be in an air independent closed cycle power generation combustion process.
  • the carbon dioxide-containing product come include one or more of a sulfur oxides, a nitrogen oxide, nitrogen, and oxygen.
  • the process can include a cryogenic process.
  • the cryogenic process can be an open cycle air dependent power generating internal combustion engine.
  • the air dependent power generating internal combustion engine can capture carbon dioxide in form liquid from the carbon dioxide containing product.
  • the air dependent power generating internal combustion engine can capture the sulfur oxides in liquid form from the carbon dioxide- containing product.
  • the air dependent power generating internal combustion engine can capture the nitrogen oxides in liquid form from the carbon dioxide-containing product.
  • the air dependent power generating internal combustion engine can capture nitrogen in liquid form from the carbon dioxide-containing product.
  • the air dependent power generating internal combustion engine can capture oxygen in liquid form, from the carbon dioxide-containing product.
  • the air dependent power generating internal combustion engine can capture one or more of carbon dioxide, sulfur oxides, nitrogen oxides, nitrogen, and oxygen in form liquid from the carbon dioxide containing product.
  • carbonaceous particles combusting the plurality of carbonaceous particles in an engine to form carbon dioxide; and concentrating the carbon dioxide.
  • the plurality of carbonaceous particles can have a mean and median size of at least about 1 microns but no more than about 45 microns.
  • the plurality of carbonaceous particles can be one or more of petroleum coke, coal, a biomass, a liquid petroleum residue, lube oil, and fuel oil.
  • the plurality of carbonaceous particles can be petroleum coke.
  • the plurality of carbonaceous particles can be coal.
  • the plurality of carbonaceous particles can be a biomass.
  • the plurality of carbonaceous particles can be a liquid petroleum residue.
  • the plurality of carbonaceous particles can be lube oil.
  • the plurality of carbonaceous particles can be a fuel oil.
  • the concentrating of the carbon dioxide is by a step of recovering the carbon dioxide by one or more of ammonia-water refrigeration and a heat recovery power cycle, organic and/or inorganic heat Rankine refrigeration and power cycles, propane and carbon dioxide compression refrigeration and power cycles, and cryogenic air processes to refrigerate the carbon dioxide.
  • the concentrating of the carbon dioxide is by a step of recovering the carbon dioxide by ammonia-water refrigeration and a heat recovery power cycle.
  • the concentrating of the carbon dioxide is by a step of recovering the carbon dioxide by an organic heat Rankine refrigeration and power cycles.
  • the concentrating of the carbon dioxide is by a step of recovering the carbon dioxide by an inorganic heat Rankine refrigeration and power cycles.
  • the concentrating of the carbon dioxide is by a step of recovering the carbon dioxide by propane and carbon dioxide compression refrigeration and power cycles. In some embodiments, the concentrating of the carbon dioxide is by a step of recovering the carbon dioxide by a cryogenic air processes to refrigerate the carbon dioxide.
  • the process can include a step of injecting at least a portion of the carbon dioxide into a hydrocarbon-containing subterranean deposit.
  • the injecting of the carbon dioxide into the hydrocarbon-containing subterranean deposit can assist in recovering at least some of the hydrocarbon contained within the subterranean deposit.
  • the plurality of carbonaceous particles can be combusted in an internal combustion engine.
  • the internal combustion engine can be a reciprocating internal combustion engine.
  • the internal combustion engine can be an internal combustion turbomachine.
  • the internal combustion engine can be a combination of a reciprocating internal combustion engine and an internal combustion turbomachine.
  • a process having the steps of providing an aqueous stream comprising one or more surfactants and a mixture of solid and liquid carbonaceous particles, combusting the mixture of solid and liquid carbonaceous particles to form carbon dioxide, recovering the carbon dioxide by a refrigeration process, and injecting at least a portion of the recovered carbon dioxide into a subterranean formation.
  • the mixture of solid and liquid carbonaceous particles can have a mean and median size of at least about 1 microns but no more than about 45 microns.
  • the solid carbonaceous particles can be one or more of petroleum coke, coal, and a biomass. In some embodiments, the solid carbonaceous particles can be petroleum coke. In some embodiments, the solid carbonaceous particles can be coal. In some embodiments, the solid carbonaceous particles can be a biomass.
  • the liquid carbonaceous particles can be one or more of petroleum residue, lube oil, and fuel oil. In some embodiments, the liquid carbonaceous particles can be a petroleum residue. In some embodiments, the liquid carbonaceous particles can be a lube oil. In some embodiments, the liquid carbonaceous particles can be a fuel oil.
  • the carbon dioxide can be recovered by one or more of ammonia-water refrigeration and a heat recovery power cycle, organic and inorganic heat Rankine refrigeration and power cycles, propane and carbon dioxide compression refrigeration and power cycles, and cryogenic air processes.
  • the carbon dioxide can be recovered by an ammonia-water refrigeration and a heat recovery power cycle.
  • the carbon dioxide can be recovered by organic heat Rankine refrigeration and power cycles.
  • the carbon dioxide can be recovered by inorganic heat Rankine refrigeration and power cycles.
  • the carbon dioxide can be recovered by a propane and carbon dioxide compression refrigeration and power cycles. In some embodiments, the carbon dioxide can be recovered by a cryogenic air process.
  • the mixture of solid and liquid carbonaceous particles can be combusted in an internal combustion engine.
  • the subterranean formation can be a hydrocarbon-containing subterranean formation.
  • the injecting of carbon dioxide can assist in recovering at least some of the hydrocarbon contained within the subterranean deposit.
  • This disclosure is to a process, method, and/or system for preparing a fuel source for internal combustion engines.
  • the fuel source can be an emulsified fuel source.
  • the fuel source can be a low-cost fuel source.
  • the process, method, and/or system of this disclosure can utilize emulsified fuel sources for internal combustion engines.
  • the fuel source can be one of an oxygen-fired combustion, air-fired combustion or a combination of oxygen- and air-fired combustion.
  • the combustion can poly-generate electrical power for oilfield consumption.
  • the combustion can generate one or more of sulfur dioxides, carbon dioxides and nitrogen dioxides.
  • One or more cryogenic gases can be one of an oxygen-fired combustion, air-fired combustion or a combination of oxygen- and air-fired combustion.
  • refrigeration processes can capture one or more of the sulfur dioxides, carbon dioxides, and nitrogen dioxides.
  • the cryogenically captured sulfur dioxides can be processed to produce one or more of elemental sulfur, sulfuric acid, and ammonium sulfate.
  • the cryogenically captured nitrogen dioxide can be processed to produce ammonium sulfate.
  • the carbon dioxide may or may not be cryogenically captured.
  • the captured carbon dioxide can be processed to produce one or more of high pressure and dense phase liquid carbon dioxide.
  • the captured carbon dioxide can be used for one or more of enhanced oil recovery and electrical or mechanical power.
  • An organic and/or inorganic Rankine cycle can be used to capture waste heat generated by the combustion process. The captured waste heat can improve the overall efficiencies of the process, method and/or system. Carbon dioxide fuel credits can be earned to offset operating (e.g., oil recovery) costs.
  • the present disclosure can provide a number of other advantages depending on the particular configuration.
  • the process, method, and/or system can be employed without significant power and pipeline infrastructure for the poly-generation of power and carbon dioxide.
  • the process, method, and/or system can also provide distributed power to oilfields within the electrical distribution and/or transmission grid - thereby displacing power transmission of faraway generation and earning distribution/transmission credits under the current Alberta infrastructure pricing.
  • Carbon dioxide can be locally generated at the oilfield using a highly efficient poly-generation process.
  • facilities can be relocated to other oilfields at the end of life and/or used to test and justify the tertiary exploitation scheme of an oil reservoir.
  • the use of oxygen can provide a high
  • each of the expressions “at least one of A, B and C”, “at least one of A, B, or C”, “one or more of A, B, and C", “one or more of A, B, or C", “A, B, and/or C", and "A, B, or C” means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.
  • each one of A, B, and C in the above expressions refers to an element, such as X, Y, and Z, or class of elements, such as Xi-Xn, Yi-Ym, and Zi-Z 0
  • the phrase is intended to refer to a single element selected from X, Y, and Z, a combination of elements selected from the same class (e.g., Xi and X2) as well as a combination of elements selected from two or more classes (e.g., Yi and Z 0 ).
  • clay refers to a finely-grained natural rock or soil material that combines one or more clay minerals with possible traces of quartz (S1O2), metal oxides (AI2O3, MgO, etc.) and organic matter.
  • Coal refers to a combustible black or brownish-black sedimentary rock usually occurring in rock strata in layers or veins called coal beds or coal seams.
  • the harder forms, such as anthracite coal can be regarded as metamorphic rock because of later exposure to elevated temperature and pressure.
  • Coal is composed primarily of carbon, along with variable quantities of other elements, chiefly hydrogen, sulfur, oxygen, and nitrogen.
  • Coal is a fossil fuel that forms when dead plant matter is converted into peat, which in turn is converted into lignite, then sub-bituminous coal, after that bituminous coal, and lastly anthracite.
  • coal refers to a solid, carbon-rich residue derived upgrading, distillation and processing of crude oil, primarily heavy crudes and bitumen.
  • emulsifier refers to a substance that stabilizes an emulsion by increasing its kinetic and/or thermodynamic stability.
  • One class of emulsifiers is known as "surface active agents", or surfactants (such as detergents).
  • Emulsifiers are compounds that typically have a polar or hydrophilic (i.e. water-soluble) part and a non-polar (i.e. hydrophobic or lipophilic) part. Because of this, emulsifiers tend to have more or less solubility either in water or in oil.
  • Emulsifiers that are more soluble in water (and conversely, less soluble in oil) will generally form oil-in-water emulsions, while emulsifiers that are more soluble in oil will form water-in-oil emulsions.
  • Emulsion refers to a mixture of two or more liquids that are normally immiscible (unmixable or unblendable). Emulsions are part of a more general class of two-phase systems of matter called colloids. Although the terms colloid and emulsion are sometimes used interchangeably, emulsion should be used when both phases, dispersed and continuous, are liquids. In an emulsion, one liquid (the dispersed phase) is dispersed in the other (the continuous phase). Emulsions contain both a dispersed and a continuous phase, with the boundary between the phases called the "interface.” Two liquids can form different types of emulsions.
  • oil and water can form, first, an oil-in-water emulsion, wherein the oil is the dispersed phase, and water is the dispersion medium. (Lipoproteins, used by all complex living organisms, are one example of this.) Second, they can form a water-in-oil emulsion, wherein water is the dispersed phase and oil is the external phase. Multiple emulsions are also possible, including a "water-in-oil-in-water” emulsion and an "oil-in-water-in-oil” emulsion.
  • homogenization refers to any of several processes used to make a mixture of two mutually non-soluble liquids the same throughout. This is commonly achieved by turning one of the liquids into a state consisting of extremely small particles distributed uniformly throughout the other liquid. Homogenization typically converts two immiscible liquids (i.e. liquids that are not soluble, in all proportions, one in another) into an emulsion (an emulsion is a type of colloid, which is a substance microscopically dispersed throughout another substance; when both the dispersed and the continuous substances are liquids, the colloid is called an emulsion). Sometimes two types of homogenization are distinguished: primary homogenization, when the emulsion is created directly from separate liquids; and secondary homogenization, when the emulsion is created by the reduction in size of droplets in an existing emulsion.
  • soap refers to a salt of a fatty acid
  • surfactant refers to a compound that lowers the surface tension (or interfacial tension) between two liquids, between a gas and a liquid, or between a liquid and a solid. Surfactants may act as detergents, wetting agents, emulsifiers, foaming agents, and dispersants.
  • Surfactants can be anionic (e.g., sulfate, sulfonate, phosphate esters, and/or carboxylates), cationic (e.g., have cationic head groups such as pH-dependent primary, secondary, or tertiary amines and/or permanently charged quaternary ammonium salts), zwitterionic (e.g., have both cationic and anionic centers attached to the same molecule such as a sultaine, cocamidopropyl betaine, phospholipid, phosphatidylserine, phosphatidylethanolamine, phosphatidylcholine, and/or sphingomyelins), or nonionic (e.g., ethoxylates, fatty acid esters of polyhydroxy compounds, amine oxides, sulfoxides, and/or phosphine oxides).
  • anionic e.g., sulfate, sulfonate, phosphate est
  • component or composition levels are in reference to the active portion of that component or composition and are exclusive of impurities, for example, residual solvents or by-products, which may be present in commercially available sources of such components or compositions.
  • the phrase from about 2 to about 4 includes the whole number and/or integer ranges from about 2 to about 3, from about 3 to about 4 and each possible range based on real (e.g., irrational and/or rational) numbers, such as from about 2.1 to about 4.9, from about 2.1 to about 3.4, and so on.
  • real (e.g., irrational and/or rational) numbers such as from about 2.1 to about 4.9, from about 2.1 to about 3.4, and so on.
  • Figure 1 depicts a system according to an embodiment of this disclosure
  • FIG. 2 depicts a system according to an embodiment of this disclosure
  • FIG. 3 depicts a system according to an embodiment of this disclosure
  • Figure 4 depicts a system according to an embodiment of this disclosure
  • Figure 5 depicts a system according to an embodiment of this disclosure
  • Figure 6 depicts a system according to an embodiment of this disclosure
  • Figure 7 depicts a system according to an embodiment of this disclosure
  • Figure 8 depicts a system according to an embodiment of this disclosure
  • Figure 9 depicts a system according to an embodiment of this disclosure
  • Figure 10 depicts a system according to an embodiment of this disclosure.
  • Figure 11 depicts a system according to an embodiment of this disclosure.
  • Figure 12 depicts a system according to an embodiment of this disclosure.
  • a high-quality carbon dioxide can be generated according to the processes, methods, and systems of this disclosure. Moreover, the high-quality carbon dioxide can be efficiently generated. The carbon dioxide can be used for enhanced oil recovery from one or more of miscible and immiscible oil reservoirs.
  • the carbon dioxide is generated by combustion of a fuel source.
  • the carbon dioxide can be generated by a closed air independent process cycle.
  • the carbon dioxide can be generated by an open-air dependent process.
  • the combustion of the fuel source poly-generates electrical power.
  • the combustion can be within an internal combustion engine.
  • the combustion can be an oxygen-fired combustion.
  • the combustion can be an air-fired combustion.
  • the poly-generate electric power can be consumed by oilfield operations.
  • the fuel source can be an emulsion fuel source.
  • the fuel source can be a low-quality emulsion fuel source.
  • the fuel source can be a low-quality inexpensive emulsion fuel source.
  • the fuel source can comprise one or more of asphaltenes, residues, coal, petroleum coke, waste fuel oils, waste lube oils, bitumen, biomass and other fuel emulsion mixtures.
  • the combustion of the fuel source can generate sulfur oxides, nitrogen oxides, carbon oxides, and other polluting emissions.
  • Some embodiments include capture of one or more of the sulfur oxides. Some embodiments include capture of one or more of the nitrogen oxides. Some embodiments include capture of one or more of the carbon oxides. Some embodiments include capture of one or more of the sulfur oxides. Some embodiments include capture of one or more of the other polluting emissions.
  • the carbon oxides generally include carbon monoxide and carbon dioxide. Generally, substantially most, if not all, of the carbon dioxide is captured. Commonly, substantially most, if not all, of the carbon monoxide is captured. It can be appreciated that to comply with the limits of government
  • the sulfur oxides can be captured by a cryogenic refrigeration process.
  • the carbon oxides a cryogenic refrigeration process.
  • the nitrogen oxides can be captured by a cryogenic refrigeration process.
  • the cryogenically captured sulfur oxides can be processed to produce one or more of elemental sulfur, sulfuric acid, and ammonium sulfate.
  • the cryogenically captured nitrogen oxide can be processed to produce ammonium sulfate.
  • the Sulphur oxides and the nitrogen oxides may or may not be cryogenically captured and an amine or ammonia process may be utilized for the capture.
  • the carbon oxide may or may not be cryogenically captured.
  • the captured carbon dioxide can be processed to produce one or more of high pressure and dense phase liquid carbon dioxide.
  • the captured carbon dioxide can be used for one or more of enhanced oil recovery and electrical or mechanical power. Waste heat recovery using an organic or inorganic Rankine cycle greatly improves the overall process efficiencies.
  • process, method and system of this disclosure can have one or more of the following features:
  • micronized solid fuels - petroleum coke, coal and biomass, as well as others fuels such as bitumen, petroleum residues, waste lube oils and fuel oils to create a fuel-water emulsion to poly-generate electrical power, carbon dioxide for enhanced oil recovery, elemental sulfur, and sulfur containing products such as sulfuric acid and/or ammonium sulfate through the use of air independent and air dependent integrated combustion process cycles.
  • turbomachines generating electrical power, and mechanical shaft power.
  • Figure 1 depicts a solid fuel material handling process 100 that takes petroleum coke and/or a mix of both low ash coal and petroleum coke feed material 120 through a main crusher system 110 (then to elevator feed silos and distribution to the mills system 108) and for mixing with an emulsifi cation product and liquid (waste) hydrocarbons to form a emulsified fuel 168 for storage in feed tanks 150.
  • the feed material 120 is fed, by a conveyor system 104, to the feed silos and then to a tower-type pulverizer 112 in series with a mineral -type pulverizer and a closed milling process 112 to provide a median, mean, and P90 size in the comminuted material typically of no more than about 90 microns, more typically of no more than about 75 microns, and more typically of no more than about 60 microns.
  • the P90 size commonly ranges from about 1 to about 55 microns, more commonly from about 2.5 to about 25 microns, and more commonly from about 5 to about 10 microns.
  • the closed milling process 112 comprises an internal cyclone classifier 122 that separates the milled material into oversized and undersized fractions.
  • the undersized fraction is the comminuted material 116 and the oversized fraction is recirculated to the mill 112 for re-milling by the closed milling process 112.
  • the final classifier 122 is inerted with nitrogen or other inert gas and separates the classified pulverized flour for emulsification.
  • the comminuted material 116 is combined and mixed with water 141 (which is removed from heated storage vessels 118) in an agitated vessel or stirred tank 126 to form a micro water slurry 128 that typically ranges from about 25 to about 75 vol.% solids and more typically from about 35 to about 65 vol.% solids.
  • An emulsification product 132 is stored in vessel 136, removed and metered from the vessel 136, transported by screw or other type of conveyor 138, and combined in an agitated vessel or stirred tank 126 with water 141 (from heated storage vessels 118) to form an emulsification liquid 143.
  • the emulsification product typically comprises one or more of: (a) from about 0.1 to about 2 wt.% of a surfactant comprising one or more of kaolinite clay, montmorillonite-smectite clay (e.g., sodium, calcium, and/or potassium bentonite), illite clay, chlorite clay, soaps, polymer products, and other surfactants; (b) from about 0.1 to about 2 wt.% of a stabilizer comprising one or more of methanol, ethylene glycol, propylene glycol, glycerol, and/or anti-freeze agent); and (c) from about 0.1 to about 2 wt.% of a viscosity breaker (or viscosity reducer) comprising typically an aromatic or nonaromatic, saturated or unsaturated, hydrocarbon having a backbone polymer chain length of from about one to about 15 carbons, more typically a hydrocarbon having a backbone polymer
  • hydrocarbon having a backbone polymer chain length of from about 3 to about 6 carbons.
  • nonaromatic hydrocarbons include one or more of methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane,, and decane and compounds comprising these hydrocarbons.
  • An example of an aromatic hydrocarbon is a polycyclic aromatic hydrocarbon, such as naphthalene (e.g., naphthalene ammonium sulphate), anthracene and phenanthrene.
  • the emulsification product can include from about 0.1 wt.% to about 1 wt.%) of other additives including one or more of a corrosion inhibitor (e.g., tolyriazole), a metal deactivator (to prevent copper, zinc, and other reactive metals from reacting with the fuel), a fungicide or biocide (to stop fungus and bacteria from growing in the fuel and to prolong fuel life), anti-oxidants (to stop fuel oxidation and reducing the formation of sediment and gum), a fuel stability foam (which is suspended in the fuel when stored to prolong fuel life), and oil anti-agglomerants.
  • a corrosion inhibitor e.g., tolyriazole
  • a metal deactivator to prevent copper, zinc, and other reactive metals from reacting with the fuel
  • fungicide or biocide to stop fungus and bacteria from growing in the fuel and to prolong fuel life
  • anti-oxidants to stop fuel oxidation and reducing the formation of sediment and gum
  • a fuel stability foam which is suspended
  • the emulsification product typically has an ash content of at least about 0.1 wt.% and more typically of at least about 2 wt.% but typically no more than about 5 wt.% and more typically no more than about 10 wt.%.
  • the median, mean, and P90 sizes of the emulsification product particles are typically of no more than about 90 microns, more typically of no more than about 75 microns, more typically of no more than about 65 microns, more typically of no more than about 60 microns, more typically of no more than about 55 microns, and more typically of no more than about 45 microns.
  • the median, mean, and P90 sizes commonly range from about 1 to about 50 m microns, more commonly from about 2.5 to about 25 microns, and more commonly from about 5 to about 10 microns.
  • the emulsification liquid 142 typically ranges from about 1 to about 50 vol.% solids and more typically from about 1 to about 20 vol.%) solids.
  • the emulsification liquid 142 is then introduced into one or more heated stirred tanks 144a-n to continue mixing the emulsification liquid 142 and heat it to a temperature commonly of from about 15 to about 90 degrees Celsius.
  • a first portion 146 of the heated and mixed emulsification liquid 143 is combined with the micro water slurry 128 in one or more heated stirred tank reactors 144 a-n to form an emulsified micro water slurry 148.
  • the emulsified micro water slurry 148 has a temperature commonly of from about 15 to about 90 degrees Celsius.
  • the emulsified micro water slurry 148 is contacted with a second portion 152 of the heated and mixed emulsification liquid 143 and passed through a first in-line mixer 154 and then contacted with a (typically waste) hydrocarbon product 140 (such as waste oils, ashphaltenes, petroleum residues, fuel oils and lube oils) from heated storage vessel 156 (which maintains the hydrocarbon product 140 in a lower viscosity liquid phase and prevents the hydrocarbon product from solidifying), while passing through a second inline mixer 156 to form an emulsified fuel feed material 158.
  • a hydrocarbon product 140 such as waste oils, ashphaltenes, petroleum residues, fuel oils and lube oils
  • the emulsified fuel feed material 158 is typically from about 0.1 to about 3 vol.%> emulsification product, from about 10 to about 70 vol.%> coal and/or coke, and from about 10 to about 70 vol.%> waste hydrocarbon product, with the remainder being water. Stated differently, the emulsified fuel feed material 158 is typically from about 0.1 to about 3 wt.%> emulsification product, from about 10 to about 70 wt.%> coal and/or coke, and from about 10 to about 70 wt.%> waste hydrocarbon product, with the remainder being water.
  • the emulsified fuel feed material 158 is forced under pressure through a homogenizer 163 (in which the solid particles and bubbles in the feed material 158 are converted into a smaller size and median and mean size distribution) and then introduced into a sealed stirred tank mixer 164 in which the feed material 158 is further agitated into an emulsified fuel 168.
  • a homogenizer 163 in which the solid particles and bubbles in the feed material 158 are converted into a smaller size and median and mean size distribution
  • a sealed stirred tank mixer 164 in which the feed material 158 is further agitated into an emulsified fuel 168.
  • the emulsified fuel 168 can be made to predetermined fuel specifications and properties for combustion in an internal combustion engine (typically with similar specifications to marine heavy fuel oil).
  • Higher viscosity grades of the emulsified fuel 168 can be preheated during use to bring their viscosity into the range suitable for fuel injection (from about 8 to about 27 cSt).
  • the emulsified fuel 166 can have a sulfur limit varying from about 1 to about 7 percent by mass and more typically from about 1 to about 4.5 percent by mass and an ash content of no more than about 2 wt.%.
  • the emulsified fuel 168 typically ranges from about 25 to about 75 vol.% solids and more typically from about 45 to about 65 vol.% solids.
  • the median, mean, and P90 size distributions of the solid particles in the emulsification fuel 168 can typically be no more than about 90 microns, more typically no more than about 75 microns, more typically no more than about 65 microns, more typically no more than about 60 microns, more typically no more than about 55 microns, and more typically no more than about 45 microns.
  • the median, mean, and P90 size distributions of the solids in the emulsification fuel 168 commonly range from about 1 to about 55 microns, more commonly from about 2.5 to about 25 microns, and more commonly from about 5 to about 10 microns
  • the emulsified fuel 168 is stored in one or more heated tanks 150, in which the emulsified fuel is heated to a temperature ranging from about 15 to about 90 degrees Celsius and mixed by agitators.
  • the emulsified fuel 168 is removed, as needed, by a screw-type pump 170 to be loaded into truck, ship, or rail haulage vehicles 174 or to a pipeline 160 for transport to a desired destination.
  • Figure 2 depicts a system for using the emulsified fuel 168 to provide a carbon dioxide gas and electrical power in the compression of a gas to be used for secondary or tertiary or other type of assisted recovery of hydrocarbons, such as light, medium, or heavy (weight) oil (collectively “enhanced oil recovery”).
  • the system can use emulsified fuels with air independent closed cycle internal combustion engines and poly-generation of electrical power for use in other parts of the system (including pumps, compressors, turbines, blowers, heaters, motors, and the like) and cryogenic carbon dioxide (carbon dioxide capture used for enhanced oil recovery or other oilfield producing processes), and convert captured sulfur dioxide to one or more of: sulfur, sulfuric acid, and ammonium sulfate products using a cryogenic capture process.
  • cryogenic carbon dioxide carbon dioxide capture used for enhanced oil recovery or other oilfield producing processes
  • the emulsified fuel 168 is delivered, via pipeline 160, to filter 202 and then fed to an internal combustion, typically low speed (e.g., from about 80 to 90 rpm), engine 200 to generate power via mechanical linkage 204 interacting with a generator 295.
  • the engines can be dual fuel (natural gas and emulsified fuel) with turbochargers and can be air independent. A two-stroke engine is commonly employed. Emissions, or the exhaust gas, from the engine 200 are passed through a self-cleaning filtration system 203 protecting the outlet a multi-stage blower compressor (turbocharger expander) exhaust system 230 from corrosion.
  • the exhaust gas 201 from the engine 200 is fed to the turbocharger blower expander exhaust system 230 to induce engine flow and reduce exhaust pressures.
  • the working fluids 207 to the inlet of the multi-stage blower compressor exhaust system 230 are recirculated carbon dioxide 209 and oxygen 211 from a cryogenic oxygen facility 210 is the oxidizing fluid to the multi-stage blower compressor system 230 inlet.
  • the exhaust gases 201 drive the turboexpander (expander part of the turbocharger) part of 230 and compresses (compressor part of the turbocharger) the stream 207 which is oxygenated carbon dioxide.
  • the exhaust gas 231 leaving the outlet of the two-stage blower compressor exhaust system 230 is pressurized by a blower compressor 232 and fed to a heat recovery system 240 that generates power, improves cycle efficiency and reduces exhaust temperatures.
  • This system 240 may be an organic or inorganic Rankine power cycle, an ammonia-water refrigeration and power cycle, or an equivalent non-ammonia water cycle with working fluids having similar physical properties to ammonia-water such as dimethyl ether (DME) and a propane mixture or steam.
  • An ammonia-based selective catalyst reduction (SCR) may be installed to control nitrogen oxides.
  • the exhaust gas portion is then fed to a second stage low grade heat recovery system 250 that generates power, improves cycle efficiency and reduces exhaust temperatures.
  • This system may also be an organic or inorganic Rankine power cycle, an ammonia-water refrigeration and power cycle, or an equivalent non-ammonia water cycle with working fluids having similar physical properties to ammonia-water such as dimethyl ether (DME) and a propane mixture or similarly compatible liquid and gases.
  • DME dimethyl ether
  • the exhaust gas 231 and water-free ethylene glycol mixture 233 from the water and ethylene glycol regenerator 290 are fed and sprayed into the tube side of a chiller system 260.
  • the chiller system 260 can be a propane refrigerant, ammonia refrigerant and products, liquid air products and/or liquid air from the cryogenic oxygen facility 210. All coolants are returned to the source on a regenerative manner.
  • the chiller system 260 outputs a combined exhaust gas/ethylene glycol/water mixture 234 with a temperature typically of no more than about -15 degrees Celsius and more typically ranging from about -35 to about -15 degrees Celsius, which is then fed to a separator 213.
  • the separator 213 separates the mixture 234 into a first portion 235 comprising most of the carbon dioxide in the cooled mixture 234 and a second portion 221 comprising most of the sulfur oxides (e.g., SOx) and ethylene glycol in the cooled mixture.
  • a first part 209 of the first portion 235 is mixed with oxygen 211 from the cryogenic oxygen air separation process 210 yielding an oxygen and carbon dioxide mixture that is fed into the inlet turbocharger of the engine and, in a second part 215 , passed to a compressor 261 to compress the carbon dioxide gas remaining in the second part 215 of the exhaust gas.
  • the compressed, cooled mixture 234 is fed to a second chiller system 262 (similar to chiller system 260) to further cool and liquify the compressed gas 234, by a conventional cryogenic air separation process as the refrigerant, or some other refrigerant from a refrigerant cycle, into a first stream 217 containing most of the oxygen and nitrogen, or the refrigerant cycle vapor 219 in the compressed gas 234 (which can be vented to the atmosphere), a second stream 219 containing cryogenic air refrigerant or some other refrigerant cycle refrigerant to cool and liquify the compressed gas 234, liquid carbon dioxide 285 is then stored in a vessel 263, and a third stream, or further cooled liquid carbon dioxide containing mostly carbon dioxide in the compressed gas 234.
  • the second stream 285 of the compressed, cooled mixture 234, which is commonly in the liquid phase and comprises at least about 80 mole%, more typically at least about 90 mole%, and more typically at least about 95 mole% carbon dioxide) is fed to a liquid carbon dioxide storage 263 in 250 psig bullet vessels.
  • the second portion 221 (which volumetrically is only a portion of the mixture 234) passes through a heat exchanger 236 (to transfer heat to the second portion 221 and cool the regenerated water and ethylene glycol mixture 233) and is introduced into the separator 270, which separates the sulfur dioxide (in the exhaust gas) from the ethylene glycol.
  • the separated sulfur dioxide 271 is fed to the sulfur plant facility 280, sulfuric acid facility 281, and/or ammonium sulfate facility 282.
  • the separated ethylene glycol 272, on the other hand, is passed through a filter 273, and the filtered and separated ethylene glycol is returned to the water and ethylene glycol regeneration plant 290. Water from the plant 290 is fed to an air cooler 291 and disposed into the oilfield.
  • the injected second stream 285 typically has an immiscible or miscible pressure ranging about from about 1000 psig to about 3700 psig.
  • the generated power is utilized within the oilfield 295 with the balance and/or all being sold.
  • ethylene glycol from the regeneration plant 290 is sprayed into the exhaust gas 231 upstream of the chiller system 260 as a
  • sulfur dioxide is liquified at - 15°C by the cryogenic oxygen facility 210 and/or another cooling cycle as described in Figure 4 (400, 500, 600); the sulfur dioxide can be processed into sulfuric acid 281, ammonia sulfate 280, or elemental sulfur 281 and is separated from the exhaust gas 231, and carbon dioxide is recycled in stream 209 to the internal combustion engine(s) 200, with the balance of the carbon dioxide following through to capture by the second chiller system 262 and disposal into the injection well 264.
  • each of the carbon dioxide and sulfur oxide e.g., sulfur dioxide and sulfur trioxide
  • a sulfur product e.g., sulfuric acid, elemental sulfur, or ammonium sulfate
  • Figure 3 depicts a system that uses emulsified fuels with air dependent open cycle internal combustion engines and poly-generation of electrical power and cryogenic carbon dioxide (carbon dioxide capture used for enhanced oil recovery or other oilfield producing processes) and converts captured sulfur dioxide to one or more of: sulfur, sulfuric acid, and ammonium sulfate products using a cryogenic capture process.
  • an emulsified fuel supply 160 is pumped, filtered, and introduced into an internal combustion, typically low speed, engine 300 to generate power.
  • the engines are dual fuel (natural gas and emulsified fuel) with turbochargers and are air dependent.
  • An exhaust blower compressor exhaust system 310 compresses the exhaust gas 312 from the engine 300 to induce engine flow and reduce exhaust pressures.
  • a heat recovery system 320 treats the compressed exhaust gas 314 to generate power, improve cycle efficiency, and reduce exhaust temperatures.
  • the system 320 may be an organic or inorganic Rankine power cycle, an ammonia-water refrigeration and power cycle, or an equivalent non-ammonia water cycle with working fluids having similar physical properties to ammonia-water such as dimethyl ether (DME) and a propane mixture or steam.
  • DME dimethyl ether
  • the treated exhaust gas 316 is cooled by an exhaust chiller system 330 (which may be a propane refrigerant, ammonia refrigerant and waste heat cycle and products, liquid air products and/or liquid air from the cryogenic oxygen facility, with all coolants being returned to the source on a regenerative manner) to form a cooled mixture 333 and an refrigerant off gas 337 (containing most of the nitrogen in the treated exhaust gas 316) (which may be vented to the atmosphere).
  • Regenerated ethylene glycol 318 from the ethylene glycol regenerator 290 can be sprayed into the exhaust flue stream (upstream of the exhaust chiller system 330) to form a combined gas 332 as a dehydration process for combustion water dewpoint control.
  • the cooled mixture 333 is introduced into a separator 335, which separates the cooled mixture 333 into a first portion 336 (comprising most of the carbon dioxide in the mixture 333) and a second portion 353 (comprising most of the sulfur oxides and ethylene glycol in the mixture 333).
  • the first portion 336 of the cooled mixture 334 is compressed by compressor 334 and fed to a second chiller system 331 (similar to chiller system 330) to form a further cooled exhaust gas 338 and a second refrigerant off gas 339 (containing most of the nitrogen in the second off gas 339) (which may be vented to the atmosphere).
  • the further cooled exhaust gas 338 is compressed in a second stage of compression by a compressor 341 to form a further compressed exhaust gas 343.
  • the further compressed exhaust gas 343 is passed through a pre-cooler 360 utilizing a Joule-Thomson "JT" valves on the carbon dioxide boil-off gas from the liquefaction separation system 350 to partially cryo-cool the exhaust gas 343.
  • the cryo-cooled exhaust gas 344 is passed through a turboexpander power generator 342 to decrease the pressure of the gas 344 and liquify most of the carbon dioxide in the gas 344.
  • the partially liquified stream 348 is introduced into a carbon dioxide separation vessel 350, with liquified carbon dioxide liquids 346 fed to storage 263 for later introduction into injection well 264 for
  • Nitrogen and oxygen are separated from the carbon dioxide, with condensables 351 being recycled, and a stream 352 of separated nitrogen plus oxygen sent to the inlet pre-cooler 360 and may be utilized as a refrigerant feed to chillers 330 and 331, then vented to atmosphere, as flue gases like nitrogen, carbon dioxide, nitrogen oxides and oxygen undergo second stage of compression and feed expander in carbon dioxide cryogenic separation.
  • Glycol antifreeze spray system in combination with other systems may or may not be utilized inside the carbon dioxide separator and/or expander outlet to control carbon dioxide snow formation (dry ice).
  • the second portion 353 of the cooled mixture 333 passes through a heat exchanger 354 to cool the regenerated ethylene glycol 318 and is introduced into the separator 270, which separates sulfur dioxide (in the exhaust gas) from the ethylene glycol.
  • the separated sulfur dioxide 271 is fed to the sulfur plant facility 280, sulfuric acid facility 281, and/or ammonium sulfate facility 282.
  • the separated ethylene glycol 272, on the other hand, is passed through a filter 273, and the filtered and separated ethylene glycol is returned to the water and ethylene glycol regeneration plant 290. Water from the plant 290 is fed to an air cooler and disposed into the oilfield 291.
  • the carbon dioxide liquids 346 are pumped from the storage vessel 263 into the injection well 264 for gas-assisted hydrocarbon recovery.
  • the carbon dioxide liquids 346 typically have an immiscible or miscible pressure ranging about from 1000 psig to about 3700 psig.
  • each of the carbon dioxide and sulfur oxide e.g., sulfur dioxide and sulfur trioxide
  • a sulfur product e.g., sulfuric acid, elemental sulfur, or ammonium sulfate
  • Figures 4A, B, and C are directed to a system comprising cycle configurations for waste heat recovery and refrigeration processes.
  • the system includes a propane or ammonia refrigeration closed compression cycle, organic or inorganic closed Rankine waste heat power cycle, closed cycle water ammonia refrigeration and/or waste heat power cycle.
  • a closed organic or inorganic waste heat recovery power cycle 400 is depicted.
  • Power is generated through pumping at design pressure a working thermal fluid at liquid conditions and changing its state to an energized gas and back to a liquid state in a closed loop.
  • the cold thermal liquid fluid is pumped from the cycle 410 to absorb waste heat energy by cross-exchanging energy at a heat source, mainly exhaust flue gas from internal combustion or an industrial process, where the thermal fluid gains energy and may or may not fully change phase or state from a liquid to a high energy gas and returns back to the cycle 420.
  • the thermal exchange fluid 420 is separated into gas and liquid by passing through successive energy heat exchangers a vaporizer 402c, preheater 402b and Recoperator 402a.
  • the separated thermal fluid gas 402 is expanded through an expansion turbine to generate power 261, the expanded and cooled expanded gas 411 is sent to a recuperator/condenser 402a to further cool and condense the thermal fluid into a liquid.
  • a recuperator/condenser 402a to further cool and condense the thermal fluid into a liquid.
  • the cooler fluid vaporizes and the vapor 420 is returned to the closed cycle 420 to extract the energy gained through a turbo-generator 261 yielding power energy.
  • the vapors are cooled by exchanging heat within the cycle and condensed back into a liquid again and stored for recycle in a low-pressure vessel 512 in a closed loop fashion.
  • Organic or inorganic liquid working fluid is utilized with an air independent and air dependent poly-generation processes.
  • FIG 4B depicts a propane, ammonia or carbon dioxide closed compression refrigeration cycle - utilizing economizer, compression, refrigerant product cooling and a Joule-Thomson "JT" valve.
  • a liquid refrigerant feed 510 is sent to cool or chill a heat source, thus cross exchanging energy with the energy source, a flue gas stream or other heat source requiring cooling and the fluid a gas refrigerant 520 is returned as a vapor.
  • the gas refrigerant return 520 partially gains waste heat energy by cooling the refrigerant stream 510 when passed through a heat exchanger 502 through cross exchanging energy streams with the gaseous refrigerant feed 510 (which loses energy).
  • the cooler gas refrigerant return 520 is compressed 261 and gains energy.
  • the gas refrigerant 520 is cooled by an air cooler 264, crossed exchanged with the returning loop where it is further cooled and sent to a Joule-Thomson "JT" pressure reducing valve where it is further cooled and liquified.
  • the liquid refrigerant is storage in the economizer 510 and may be pumped feed or feed without a pump at design pressure for recirculation in a closed loop.
  • the working fluid may be propane, ammonia, carbon dioxide or another equivalent commercial refrigerant.
  • Figure 4C depicts a system 600 having an integrated ammonia- water cycle or an equivalent liquid and vapor fluids with an organic and inorganic cycle to the ammonia- water cycle.
  • the refrigeration cycle is a closed refrigeration and/or power generation process that extracts low grade waste heat from any energy stream to generate power and/or to refrigerate an energy stream.
  • a liquid thermal refrigerant fluid (ammonia at -37 °C and design pressure) 610 is supplied from the closed cycle to a high/low grade waste heat source that requires cooling or chilling, where the ammonia refrigerant exchanges energy with the energy source and changes state into a gas, the high energy gas 620 is returned to the cycle where it is absorbed into the water-ammonia solution 662, the ammonia absorption into the water makes aqueous ammonia and is exothermic requiring cooling through an air cooler 264, by cooling the absorber aqueous ammonia fluid it will also absorb large amounts of ammonia vapor.
  • the water-ammonia mix is pumped from the absorber at the designed pressure to an intercooler where the aqueous ammonia exchanges heat with recycled water from the ammonia generator 670.
  • the strong ammonia solution is regenerated by a heat source that separates and drives off the ammonia vapor from the aqueous ammonia leaving water to re-feed the absorber going through and cross exchanger back into the absorber to absorb more ammonia vapor in a closed loop.
  • the pump discharge design pressure sets the pressure of the system.
  • Vapor ammonia at a maximum temperature and set design pressure conditions at the regenerator (10-15 bar) is further separated of any water carryover 610a and is expanded through a turbo-generator to yield power 650, or cooled with an air cooler and expanded through a Joule Thomson "JT" valve to make a liquid refrigerant 610.
  • the ammonia refrigerant 610 may be used for cooling a stream or waste heat recover returning to the absorber 620.
  • a waste heat source may also be used to regenerate the aqueous ammonia mix to ammonia vapor and water in the closed loop cycle through the regenerator 402a.
  • a thermal fluid other than ammonia 640 may exchange heat with the regenerator 402a.
  • the generator 670 is a higher pressure system and the absorber 660 is a lower pressure system, pressure control is necessary to the absorber.
  • Figure 5 depicts a system 280 that takes sulfur dioxide captured from a pressurized combustion flue gas stream and then reacts the sulfur dioxide with ammonia to produce ammonium sulfate. Pressurized ammonia to ammonium sulfate can capture sulfur oxides form a high value fertilizer pellet.
  • the sulfur dioxide-containing gas stream 702 is introduced into an absorber reactor 700, which reacts hydrous ammonia with sulfur dioxide to form ammonium sulfate crystals. Unreacted sulfur dioxide vapors 704 are collected at the top of the absorber reactor 700 and subjected to a vapor recompression process 710 that recycles unreacted sulfur dioxide vapors 703 back to the absorber reactor 700.
  • Liquid ammonia 712 is removed from liquid ammonia storage 720 and introduced into the absorber reactor 700.
  • Ammonium sulfate crystals 714 are removed from the absorber reactor 700 and subjected to cyclone dewatering, decanting, and a filter-press system 730.
  • Ammonium sulfate crystals 716 output from the system 730 are then subjected to an ammonium sulfate crystal dryer, compactor, pelletizer, and packaging system 740.
  • a depressurization system 750 is provided to maintain system pressure within desired limits.
  • FIG. 6 depicts a system 281 that takes sulfur dioxide from a pressurized combustion flue gas stream and manufactures sulfuric acid through a catalytic converter process.
  • a sulfur dioxide-containing stream 802 is introduced into a sulfur dioxide dryer 810 that removes moisture from the sulfur dioxide-containing gas stream 802.
  • the dried gas stream 812 is then introduced into a multistage catalytic bed converter reactor 820 that reacts sulfur dioxide with air 814 to produce sulfuric acid.
  • the air 814 is passed through an air filtration, compression and dryer 830 to supply the converter reactor with air 814.
  • Heat exchanger economizers 840 and temperature control reheater 841 maintain the reactor 820 at a desired operating temperature.
  • Sulfuric acid 822 is removed from the reactor 820 and passed through intermediate and final stage acid absorbers 860 and 850.
  • the collected sulfuric acid 824 is stored in acid storage 870 for shipment.
  • Figure 7 depicts a system 282 that takes sulfur dioxide from a pressurized combustion flue gas stream and manufactures an elemental sulfur product through the hydrogeneration of sulfur dioxide into hydrogen sulfide (the reaction of sulfur dioxide and hydrogen sulfide in a Claus process manufactures elemental sulfur).
  • a first portion 904 of the sulfur dioxide-containing stream 902 is introduced into a first, second and third stage sulfur reactors 920, 921, and 922 and first, second, and third stage liquid sulfur condensers 930, 931, and 932, respectively, with the resulting elemental liquid sulfur being stored in storage 990 for later shipment and the waste gas being directed to the upstream exhaust gas system 933.
  • a second portion 908 of the sulfur dioxide-containing stream 902 is passed through a hydrogen reactor 950, waste heat boiler 960, and a water quench system 970, with the product being introduced into the first, second, and third stage sulfur reactors 920, 921, and 922.
  • Hydrogen is provided to the hydrogen reactor by a hydrogeneration reactor 940.
  • a multi-stream reducing gas generator 910 can receive multiple air streams to form a single air stream 912. The air stream is passed through a waste heat boiler 980 and directed to the hydrogeneration reactor 940.
  • Figure 8 depicts a cryogenic air separation system 1000 that produces both liquid oxygen for air independent combustion and cryogenic air products as a process refrigerant.
  • the system can not only generate liquid oxygen for air independent combustion but also a cryogenic refrigerant for sulfur oxides and carbon dioxide capture.
  • Air 1002 is passed through air filtration, water separation, mole sieve air dryer, multistage air compressors and a cooler (denoted collectively by reference 1060).
  • the resulting air stream 1004 and refrigerator return 1041 are introduced into a reverse exchanger core box 1050 to form a cooler air stream 1008.
  • the cooler air stream 1008 is next introduced into an upper and lower pressure and lower high-pressure column separator 1070 with internal reboiler.
  • Various gas streams are exchanged between the separator 1070 and super-heater core box 1040.
  • a refrigerant return 1041 from a cooler or chiller system as described in figure 2 is passed through the reverse exchanger core box 1050 to form gas stream 1014, and the gas stream 1014 is passed through a turbo-expander generator to reduce pressure and temperatures to cryogenic levels and reintroduced into the separator 1070.
  • Cold liquid air products from the bottom of 1042 or stream 1016 is fed to the coolers or chillers as described in figure 2 (260, 262, 219).
  • Liquid nitrogen 1021 recovered from the reverse exchanger core box 1050 and super-heater core box 1040 is stored in liquid nitrogen storage 1010.
  • Liquid oxygen 1023 recovered from the upper and lower pressure and lower high-pressure column separator 1070 is stored in liquid oxygen storage 1020.
  • One of the gas streams output by the reverse exchanger core box 1050 supplies oxygen to the cryogenic oxygen facility 210 and internal combustion air independent engine power generator sets 910. Cold air products from stream 1016 feed the chiller systems with the return to stream 1041.
  • first and second engine (low speed) generators 200a,b are configured to receive, as fuel, an emulsified fuel 168 or natural gas 1012 or a combination thereof and produce power 1008 and an exhaust gas 201.
  • the exhaust gas 201 is passed sequentially through medium and high pressure steam coils 1004 (which also combust the emulsified fuel 168, methane 1012, or a combination thereof) and exchange water and steam streams 1020 with a steam generator 1016 to produce power 1008), a selective catalytic reducer (SCR) 1024 (which converts nitrogen oxides (NOx) into diatomic nitrogen (N 2 ) using anhydrous ammonia, aqueous ammonia, or urea as a reactant and a ceramic catalyst coated with a metal oxide, zeolite, activated carbon, or precious metal) to remove most of the NOx from the exhaust gas 201, and a low pressure steam coil 1028 to provide a treated exhaust gas 1032.
  • SCR selective catalytic reducer
  • the treated exhaust gas 1032 commonly comprises no more than about 5 mole% molecular oxygen, more commonly no more than about 2.5 mole% molecular oxygen, and more commonly no more than about 1 mole% molecular oxygen.
  • a portion 1036 of the treated exhaust gas 1032 can be vented to atmosphere.
  • the treated exhaust gas 1032 passes through a blower to increase pressure and is introduced into an electrostatic precipitator 1036 or other particulate separator (such as a baghouse) to remove most of the soot and other particulates and provide a further treated exhaust gas 1040.
  • the separated further treated exhaust gases 1040 are combined and introduced into a flue gas
  • desulfurization process 282 which uses anhydrous or aqueous ammonia, oxidizing air, and water to convert most of the sulfur oxides into an ammonia sulfate 1044 for further processing and a treated gas stream 1045.
  • the treated gas stream 1045 is introduced into an amine process 1048 to capture most (95% mole% or more) of the carbon dioxide in the treated gas stream 1045 in a carbon dioxide-containing stream 1052 and form a purified gas stream 1050.
  • the amine process 1048 uses aqueous solutions of various alkylamines (commonly referred to simply as amines) to capture the carbon dioxide (CO2) from the treated gas stream 1045.
  • the purified air stream (mostly nitrogen and some traces of other gases 1050) passes through a temperature control reheater 841 to cool the product diatomic nitrogen as an off-gas 1054, which is released to atmosphere.
  • the off gas 1050 which is mostly nitrogen may be compressed 1057 and used for an enhanced oil recovery as a pressuring oil reservoir medium instream of another medium such as water or carbon dioxide and introduced into the injection well 264.
  • the captured carbon dioxide gas stream 1052 is compressed by a compressor 1056 to form a compressed gas 1060 and introduced into a glycol or molecular sieve dehydrator 1064 to remove most of the water and form first and second carbon dioxide-rich products 1068a and b.
  • the first carbon dioxide-rich product 1068a is compressed by a compressor 1069 and subjected to cryogenic liquefaction 1070 by a refrigeration package 1072 (discussed above with reference to the chiller systems) to form a liquid phase carbon dioxide liquids 346.
  • the carbon dioxide liquids 346 are pumped from the storage vessel 263 into the injection well 264 for gas-assisted hydrocarbon recovery.
  • the carbon dioxide liquids 346 typically have an immiscible or miscible pressure ranging about from 1000 psig to about 3700 psig.
  • the second carbon dioxide-rich product 1068b is compressed by compressor 1074, passed through a temperature control cooler 841 and introduced at a pressure of from about 1000 psig to about 3700 psig into the injection well 264.
  • the enhanced oil recovery process involving carbon dioxide injection yields a field produced gas 1078.
  • the field produced gas 1078 which contains hydrogen sulfides, carbon dioxide, and lighter hydrocarbons, such as methane, is compressed by compressor 1056, and the compressed field gas 1080 introduced into sour gas membranes 1082 to produce a hydrocarbon and hydrogen sulfides containing gas 1084 (containing most of the hydrocarbons and hydrogen sulfides in the field gas 1080), which is directed to sour gas processing 1088 for removal of hydrogen sulfides and further natural gas processing, and a carbon dioxide-rich gas stream 1090 (containing most of the carbon dioxide in the field gas 1080).
  • the carbon dioxide-rich gas 1090 is introduced into the glycol or molecular sieve dehydrator 1064 discussed above to remove all the water moisture.
  • Figure 10 depicts another system configuration for producing power and carbon dioxide-rich gas products.
  • the process is substantially the same as the process of Figure 9 except that the flue gas desulfurization and single-stage amine processes 282 and 1048 are replaced by a two-stage amine process 1104.
  • a first amine stage removes all or most of the SOxfrom the exhaust gases 1040 to form sulfuric acid 1108, the second amine stage removes most (95% Mole% or more) of the carbon dioxide from the further treated exhaust gases 1040 to form the purified gas stream 1052, and an off-gas 1116 comprises most of the diatomic nitrogen in the further treated exhaust gases 1040.
  • the sulfur dioxide acid-containing gas 1106 is introduced into either a wet sulfuric acid process 1108 or a sulfur plant with hydrogenation and tail gas cleanup 1112.
  • the off-gas 1116 passes through a temperature control cooler 841, with the off-gas being either vented to atmosphere or compressed by compressor 1120 and injected into an injection well for enhanced oil recovery.
  • an embodiment of the exhaust gas treatment process 1200 is depicted. Referring to Figure 11, the exhaust gas 201 is passed into a boiler 1202 comprising high pressure, medium pressure and low-pressure coils 1204, 1208, and 1212, respectively, and to an SCR 1024 and an economizer 1216.
  • Steam 1252 from the medium pressure coil 1208 passes through a separator 1220 to form a water condensate 1256, which is directed to blowdown vessel 1224 to atmospheric pressure for discharge, and a steam-containing gas stream 1260, which is recycled to the high-pressure coil 1204.
  • High pressure steam 1264 is directed to the extraction turbine 1228 for generation of power 1008.
  • the low-pressure gas 1268 is passed through heat exchanger 1232, or steam condenser, to condense the steam and form a cooled condensate stream 1272.
  • the condenser is part of a cooling water circuit .
  • the cooled steam condensate stream 1272 is directed to a blowdown vessel 1240 and the water condensate pumped 1236 to the economizer to close the thermal steam energy cycle.
  • the low-pressure coil 1212 reheats condensate 1256 from the separator 1220 to form the low-pressure steam 1252.
  • the steam condensable from 1240 are pumped 1236 to the economizer 1216 for energy exchange with flue gases 1032 increasing cycle efficiency.
  • Inter-stage steam 1270 is removed from the medium pressure coil 1208 to run the compressor 1244 and to expand thermal energy 1228 to the turbo-generator.
  • Low pressure steam 1278 from the compressor turbine 1244 being a low pressure steam supply for the amine, dehydration, and other processes.
  • Stream 1274 is extraction steam from the turbo-generator for reheat at constant pressure through 1208 to supply both compressor 1244 and turbo-generator power 1008.
  • Figure 12 depicts a flue gas desulfurization process 280 according to an
  • the nozzles generate fine droplets of ammonia-containing reagent to ensure intimate contact of reagent with the incoming sulfur dioxide -containing gas (not shown).
  • the sulfur dioxide reacts with ammonia in an upper half 1316 of the absorber 700 to produce ammonium sulfite.
  • the bottom 1320 of the absorber 700 serves as an oxidation tank where air 1312 oxidizes the ammonium sulfite to ammonium sulfate.
  • the resulting ammonium sulfate solution 1324 is pumped back to the spray nozzle headers at multiple levels in the absorber.
  • the takeoff product solution 1336 is pumped to a solids recovery system consisting of a hydro cyclone 1340 and centrifuge or filter press 1344 to concentrate the ammonium sulfate product prior to drying and packaging. All liquids (hydro cyclone overflow and centrifuge centrate) are directed back to a slurry tank 1348 and then re-introduced into the absorber ammonium sulfate recycle stream 1352. Fresh ammonia is stored in vessel 1370 for introduction into the absorber 700. Various coolers are present to maintain desired operating temperatures in the system. Many different amines can be used in gas treating, including Diethanol amine (DEA), Monoethanolamine (MEA),
  • Methyldiethanolamine MDEA
  • Diisopropanolamine DIP A
  • Aminoethoxyethanol Diglycolamine
  • DGA Aminoethoxyethanol
  • alkanolamines DEA, MEA, and MDEA alkanolamines
  • FIG 13 depicts a carbon dioxide capture process 1400 according to an embodiment.
  • the amine gas treating process 1400 includes an absorber unit 1404 and a regenerator unit 1408 as well as accessory equipment (such as amine charge tank 1450 containing recycled amine solution 1454, heat exchanger 402 to remove heat from any of the carbon dioxide-rich gas streams discussed above, coolers 1236 to maintain desired operating temperatures, and coalescer 1458 to remove amine mist).
  • accessory equipment such as amine charge tank 1450 containing recycled amine solution 1454, heat exchanger 402 to remove heat from any of the carbon dioxide-rich gas streams discussed above, coolers 1236 to maintain desired operating temperatures, and coalescer 1458 to remove amine mist).
  • the downflowing amine solution 1408 absorbs FhS and CO2 from the up-flowing sour gas to produce a sweetened gas stream 1412 (e.g., a gas free or substantially free of hydrogen sulfide and carbon dioxide) as a product and an amine solution 1416 rich in the absorbed acid gases.
  • the resultant rich amine solution 1416 is routed into the regenerator 1408 (commonly a stripper with a reboiler) to produce regenerated or lean amine 1420 that is recycled for reuse in the absorber 1404.
  • the overhead gas stream (not shown) from the regenerator is concentrated H2S and CO2.
  • the present disclosure includes providing devices and processes in the absence of items not depicted and/or described herein or in various embodiments, configurations, or aspects hereof, including in the absence of such items as may have been used in previous devices or processes, e.g., for improving performance, achieving ease and ⁇ or reducing cost of implementation.

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Abstract

L'invention concerne un procédé qui comprend la formation d'une suspension aqueuse épaisse de particules carbonées ; la combustion de la suspension aqueuse épaisse dans un moteur à combustion interne pour former un produit contenant du dioxyde de carbone ; et l'injection d'au moins une partie du produit contenant le dioxyde de carbone dans un puits pour contribuer à récupérer un hydrocarbure d'un dépôt souterrain.
PCT/US2018/052473 2017-09-22 2018-09-24 Procédé de poly-génération de dioxyde de carbone (co2) pour une récupération tertiaire d'huile améliorée, et génération d'énergie sans carbone pour l'exploitation de champs pétrolifères à l'aide d'un combustible résiduaire émulsifié à faible coût Ceased WO2019060844A2 (fr)

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US7699104B2 (en) * 2007-05-23 2010-04-20 Maoz Betzer Tsilevich Integrated system and method for steam-assisted gravity drainage (SAGD)-heavy oil production using low quality fuel and low quality water
US9334844B2 (en) * 2013-09-27 2016-05-10 Motiv Engines LLC Reciprocating internal combustion engine

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